Petroleum refiners often produce desirable products such as turbine fuel, diesel fuel, middle distillates, naphtha, and gasoline boiling hydrocarbons among others by hydrocracking a hydrocarbon feed stock derived from crude oil or heavy fractions thereof. Feed stocks subjected to hydrocracking can be vacuum gas oils, heavy gas oils, and other hydrocarbon streams recovered from crude oil by distillation. For example, a typical heavy gas oil comprises a substantial portion of hydrocarbon components boiling above about 371° C. (700° F.) and usually at least about 50 percent by weight boiling above 371° C. (700° F.), and a typical vacuum gas oil normally has a boiling point range between about 315° C. (600° F.) and about 565° C. (1050° F.).
Hydrocracking is a process that uses a hydrogen-containing gas with suitable catalyst(s) for a particular application. In general, there are three main configurations of hydrocracking units in use today: a single-stage hydrocracking system, a separate hydrotreat and hydrocracking system, and a two-stage hydrocracking system. In the single-stage hydrocracking system, the feed is first hydrotreated and then routed to a hydrocracking zone prior to a fractionation zone. In the separate hydrotreat and hydrocracking system, the feed is hydrotreated and then routed through the fractionation zone prior to the hydrocracker. In the two-stage hydrocracking system, the feed is hydrotreated, routed to a first hydrocracking zone, and then the effluent from the first hydrocracking zone is routed through the fractionation zone prior to a second hydrocracking zone.
Hydrocracking is currently accomplished by contacting the selected feed stock in a reaction vessel or zone with a suitable catalyst under conditions of elevated temperature and pressure in the presence of hydrogen as a separate phase in a three-phase reaction system (gas/liquid/solid catalyst). Such hydrocracking is commonly undertaken in a trickle-bed reactor where the continuous phase throughout the reactor is gas and not liquid.
In the trickle bed reactor, an excess of the hydrogen gas is present in the continuous gaseous phase. In many instances, a typical trickle-bed hydrocracking reactor requires up to about 10,000 SCF/B of hydrogen at pressures up to 17.3 MPa (2500 psig) to effect the desired reactions. In these systems, because the continuous phase throughout the reactor is a gas-phase, large amounts of hydrogen gas are generally required to maintain this continuous phase. However, supplying such large supplies of gaseous hydrogen at the operating conditions needed for hydrocracking adds complexity and expense to the system.
For example, in order to supply and maintain the needed amounts of hydrogen in a continuous gas-phase system, the resulting effluent from the cracking reactor is commonly separated into a gaseous component containing hydrogen and a liquid component. The gaseous component is directed to a compressor and then recycled back to the reactor inlet to help supply the large amounts of hydrogen gas needed to maintain the continuous gaseous phase therein. Conventional trickle-bed hydrocracking units typically operate up to about 17.3 MPa (2500 psig) and, therefore, require the use of a high-pressure recycle gas compressor in order to provide the recycled hydrogen at necessary elevated pressures. Often such hydrogen recycle can be up to about 10,000 SCF/B, and processing such quantities of hydrogen through a high-pressure compressor adds the complexity and cost to the hydrocracking unit.
Two-phase hydroprocessing (i.e., a liquid hydrocarbon stream and solid catalyst) has been proposed to convert certain hydrocarbon streams into more valuable hydrocarbon streams in some cases. For example, the reduction of sulfur in certain hydrocarbon streams may employ a two-phase reactor with pre-saturation of hydrogen rather than using a traditional three-phase system. See, e.g., Schmitz, C. et al., “Deep Desulfurization of Diesel Oil: Kinetic Studies and Process-Improvement by the Use of a Two-Phase Reactor with Pre-Saturator,” Chem. Eng. Sci., 59:2821-2829 (2004). These two-phase systems only use enough hydrogen to saturate the liquid-phase in the reactor. As a result, the reactor systems of Schmitz et al. have the shortcoming that as the reaction proceeds and hydrogen is consumed, the reaction rate decreases due to the depletion of the dissolved hydrogen.
Other uses of liquid-phase reactors to process certain hydrocarbonaceous streams require the use of diluent/solvent streams to aid in the solubility of hydrogen in the unconverted oil feed and require limits on the amount of hydrogen in the liquid feed streams. For example, liquid-phase hydrotreating of a diesel fuel has been proposed, but requires a recycle of hydrotreated diesel as a diluent blended into the oil feed prior to the liquid-phase reactor. In another example, liquid-phase hydrocracking of vacuum gas oil is proposed, but likewise requires the recycle of hydrocracked product into the feed to the liquid-phase hydrocracker as a diluent. These prior art systems also may permit the presence of some hydrogen gas in the liquid-phase reactors, but the systems are limited to about 10 percent or less hydrogen gas by total volume. Such limits on hydrogen gas in the system tend to restrict the overall reaction rates and the per-pass conversion rates in such liquid-phase reactors.
Because hydrotreating and hydrocracking typically require large amounts of hydrogen to effect their conversions, a large hydrogen demand is still required even if these reactions are completed in liquid-phase systems. As a result, to maintain such a liquid-phase hydrotreating or hydrocracking reaction and still provide the needed levels of hydrogen, the diluent or solvent of these prior liquid-phase systems is required in order to provide a larger relative concentration of dissolved hydrogen as compared to unconverted oil to insure adequate conversions can occur in the liquid-phase hydrotreating and hydrocracking zones. As such, larger and more complex liquid-phase systems are needed to achieve the desired conversions that still require large supplies of hydrogen.
Although a wide variety of process flow schemes, operating conditions and catalysts have been used in commercial petroleum hydrocarbon conversion processes, there is always a demand for new methods and flow schemes that provide more useful products and improved product characteristics. In many cases, even minor variations in process flows or operating conditions can have significant effects on both quality and product selection. There generally is a need to balance economic considerations, such as capital expenditures and operational utility costs, with the desired quality of the produced products.